10-K 1 a2043140z10-k.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2000. [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from __________ to ____________. Commission File Number 1-11566 MARKWEST HYDROCARBON, INC. (Exact name of registrant as specified in its charter) DELAWARE 84-1352233 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 155 INVERNESS DRIVE WEST, SUITE 200, ENGLEWOOD, CO 80112-5000 (Address of principal executive offices) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 303-290-8700 Securities registered pursuant to Section 12(b) of the Act: COMMON STOCK, $0.01 PAR VALUE, AMERICAN STOCK EXCHANGE Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ No / / Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ____ The aggregate market value of voting common stock held by non-affiliates of the registrant on February 27, 2001, was $32,455,465. The number of shares outstanding of the registrant's common stock as of February 27, 2001, was 8,568,641. DOCUMENTS INCORPORATED BY REFERENCE The information required by Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy statement to be filed pursuant to Regulation 14A with respect to the 2001 annual meeting of stockholders. 1 MARKWEST HYDROCARBON, INC. FORM 10-K TABLE OF CONTENTS

Page ---- PART I Items 1. and 2. Business and Properties General................................................................. 3 Strategy................................................................ 3 Segments................................................................ 3 Significant 2000 and 2001 Developments.................................. 3 Gathering, Processing and Marketing..................................... 5 Exploration and Production.............................................. 7 Seasonality............................................................. 8 Competition ............................................................ 9 Operational Risks and Insurance......................................... 9 Governmental Regulation................................................. 9 Environmental Matters................................................... 10 Employees............................................................... 10 Forward-Looking Information............................................. 10 Item 3. Legal Proceedings................................................. 10 Item 4. Submission of Matters to a Vote of Security Holders............... 11 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters............................................... 11 Item 6. Selected Financial Data........................................... 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......................................... 13 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........ 17 Item 8. Financial Statements and Supplementary Data....................... 19 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......................................... 37 PART III Item 10. Directors and Executive Officers of the Registrant................ 37 Item 11. Executive Compensation............................................ 37 Item 12. Security Ownership of Certain Beneficial Owners and Management.... 37 Item 13. Certain Relationships and Related Transactions.................... 37 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 37

Glossary of Terms Bbls barrels Bcf billion cubic feet of natural gas Btu British thermal unit, an energy measurement EBITDA earnings before gain on sale, interest income, interest expense, income taxes, depreciation, depletion and amortization; a cash flow financial measure commonly used in the oil and gas industry MM million Mcf thousand cubic feet of natural gas Mcfd thousand cubic feet of natural gas per day Mcfe thousand cubic feet of natural gas equivalent MMBtu million British thermal units, an energy measurement MMcf million cubic feet of natural gas MMcfd million cubic feet of natural gas per day NGL natural gas liquids, such as propane, butanes and natural gasoline One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas. 2 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL MarkWest Hydrocarbon, Inc., and its subsidiaries (referred to collectively as the "Company" or "MarkWest") provide natural gas processing and related services and produce natural gas. The Company's natural gas processing and related activities (its gathering, processing and marketing segment) include providing compression, gathering, treatment and NGLs extraction services to natural gas producers and pipeline companies. Additionally, MarkWest fractionates NGLs into marketable products and purchases and markets natural gas and NGLs. MarkWest provides natural gas processing and related services through its modern, efficient plant and pipeline systems. Increased drilling for natural gas to meet expanding demand is driving growth for MarkWest's specialized services. Natural gas producers are increasingly outsourcing the complex task of converting raw natural gas produced at the wellhead to marketable natural gas and natural gas liquids. MarkWest is the largest processor of natural gas in Appalachia and the Company owns the only sour gas gathering and processing facilities in western Michigan. The Company also produces natural gas in the Rocky Mountains and Michigan (its exploration and production segment). The Company was founded as a partnership in 1988 and incorporated in Delaware and completed its initial public offering in 1996. The Company's principal executive office is located at 155 Inverness Drive West, Suite 200, Englewood, Colorado, 80112-5000, and its telephone number is (303) 290-8700. MarkWest maintains an NGL marketing office in Columbus, Ohio and a gas marketing and Appalachia producer relations office in Pittsburgh, Pennsylvania. STRATEGY MarkWest's strategy is to provide trend-line profit growth exceeding 15 percent annually by (1) increasing volumes of natural gas processed and volumes of NGLs produced and marketed; and (2) by increasing its natural gas production. In its gathering, processing and marketing segment, the Company focuses on geographic core areas where natural gas production is expected to increase, providing opportunities for reinvestment. This focus allows MarkWest to capitalize on its infrastructure for the benefit of its customers and its shareholders. Innovative engineering, cost-efficient operations and effective NGL marketing are core competencies of the Company. MarkWest also uses exploration to enhance its gas processing business. In its exploration and production segment, the Company focuses on lower-risk exploitation rather than exploration. The Company aims to reduce earnings volatility through emphasis in its business development efforts on fee-based services not susceptible to changes in commodity prices (in its gathering, processing and marketing segment) and through increasing hedging activities in 2001 and beyond (in both segments) when market conditions permit. Fee-based services have increased to account for about 40 percent or more of gross margins in 2001 from less than 10 percent seven years ago. SEGMENTS The Company's business activities are segregated into two segments: gathering, processing and marketing, and exploration and production of natural gas. Gathering, processing and marketing are concentrated in two core areas: the significant gas-producing basin in the southern Appalachian region of eastern Kentucky, southern West Virginia, and southern Ohio (the "Appalachian Core Area" or "Appalachia"); and the developing basin in western Michigan (the "Michigan Core Area" or "Michigan"). Exploration and production activities are concentrated in the Rocky Mountains and eastern Michigan. These segments are analyzed independently by management and derive revenue from different sources. For financial information related to each segment, see RESULTS OF OPERATIONS, in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, as well as Note 12, SEGMENT REPORTING, in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. SIGNIFICANT 2000 AND 2001 DEVELOPMENTS Gathering, Processing and Marketing During 2000, the two-phased expansion of the company's Appalachian infrastructure continued. Phase I expansion was completed in February 2000 and Phase II is in progress for completion expected by mid-2001. Phase I expansion added a new 75 MMcfd, mechanical refrigeration, NGL extraction plant ("Maytown") in southern Kentucky and nearly doubled the capacity, from 350,000 gallons per day to 600,000 gallons per day, of the Company's fractionator ("Siloam") in northern Kentucky. Revenues to be derived from the expansion are primarily fee and percent-of-proceeds based, which differ from MarkWest's historical commodity-based contracts. Finally, MarkWest acquired a 40-mile NGL pipeline in West Virginia. This pipeline, together with MarkWest's existing pipeline and a pipeline leased in 1999, forms a continuous 180-mile pipeline network through the 3 southern portion of the Appalachia Basin. The pipeline connects MarkWest's new Maytown gas plant to MarkWest's Siloam fractionator and significantly reduces feedstock transportation costs from another of MarkWest's gas plants-Boldman. MarkWest's Kenova gas plant was already connected to the pipeline. On February 1, 2000, MarkWest assumed operation of the Company-owned Boldman extraction plant from Columbia Gas Transmission Corporation ("Columbia"). Boldman is located in Kentucky. In March 2000, MarkWest acquired the Cobb, West Virginia, natural gas liquids (NGLs) extraction plant from Columbia. NGLs extracted at Boldman and Cobb have been and will continue to be fractionated into propane, butane and other liquids at the Company's Siloam plant. Phase II involves construction of the Kermit dewpoint control plant and expanding MarkWest's Kenova NGL extraction plant, increasing MarkWest's total production to 550,000 gallons per day. Phase II started construction in October 2000 and is targeted for completion and startup in mid-2001. Capital spending for the Phase I and II expansions is estimated at $14 million and $13 million, respectively. To keep pace with the growing Appalachia NGL production, MarkWest has been adding to its marketing infrastructure-additional terminals, tank railcars, pressurized trailers and new and larger loading facilities. Over the period 1999-2001, MarkWest is investing $8 million in additional marketing assets. In March 2000, MarkWest opened a new propane terminal at Lordstown, Ohio. Lordstown is located about 300 truck miles northeast of MarkWest's Siloam fractionation plant and accesses new retail markets. In September 2000, MarkWest leased 60 additional railcars. In May 2000, MarkWest entered into a two-year marketing agreement with a propane retailer for an exclusive supply agreement for their propane requirements for 17 retail bulk plants in Ohio and Kentucky. MarkWest is also leasing additional propane storage space. The agreement will involve about 30 million gallons per year of propane sales, primarily from MarkWest's Siloam fractionation facilities. MarkWest also bought twelve pressurized tank trailers to serve this supply arrangement. Although the Company's favorable year 2000 financial performance met Company objectives, events since December 2000 have proved to be more challenging. Futures prices for natural gas have risen dramatically, and prices for NGLs have stayed essentially flat. A large portion, about 75 percent, of MarkWest's processing services for gas producers in Appalachia involves extracting NGLs from inlet gas streams and replacing the equivalent heat content with dry natural gas purchased in the spot or forward markets. This part of the Company's operating margin depends on a positive spread between NGL prices and natural gas costs. Effective February 1, 2001, the Company provided producers with an alternative processing contract that provides for additional compensation to the Company when processing margins are low and reduced compensation when processing margins are high. To date, about 65 producers (accounting for a minority share of the volume) out of approximately 325 have agreed to the new contract. If producers elect to remain with the existing contract, the Company has stated that it will return the replacement natural gas at a later date, as it believes is permitted under the existing contract, such that MarkWest can earn a reasonable fee for its services. This is not an isolated situation with MarkWest-nationwide, producers and processors are renegotiating their processing agreements due to the relatively high cost of natural gas. These new arrangements provide producers the capacity necessary to support their increasing production. See also ITEM 3 - LEGAL PROCEEDINGS of this Form 10-K. Exploration and production In the third quarter of 2000, the Au Gres field in eastern Michigan began producing from an initial well after completion of necessary surface facilities. By year-end 2000, the well was producing 2,000 Mcf per day, with reserves estimated at nearly 3 billion cubic feet (Bcf). The next well is expected to be completed late first quarter 2001, with further expansions possible in late 2001. The Company's interest is 68 percent until payout, reverting to 23 percent, with an option to acquire an additional 23 percent. In January 2001, MarkWest acquired additional natural gas production properties and gathering systems in New Mexico's San Juan Basin for $5.625 million. The properties cover 4,800 acres and 40 producing gas wells containing 3.9 Bcf of proved developed reserves and 3.0 Bcf of proved, undeveloped reserves, net to MarkWest. The purchase also includes 11 miles of gathering pipelines. MarkWest is the operator of both the production and gathering systems, with initial production of 1,200 thousand cubic feet per day (Mcfd) net to MarkWest. Corporate In May 2000, MarkWest began trading under a new ticker symbol-MWP-on the American Stock Exchange. 4 In June 2000, MarkWest expanded its credit facility from $50,000,000 to $65,000,000, added a third bank and extended its term by one year to December 31, 2006. This larger credit facility gives the company greater financial flexibility to make acquisitions and develop new projects in the growing natural gas industry. GATHERING, PROCESSING AND MARKETING APPALACHIA The Company owns and operates in Appalachia five gas processing facilities, one fractionation plant, an NGL pipeline and three propane terminals. Certain information concerning the Appalachian assets is summarized in the following tables:

For the Year Ended Year December 31, 2000 Acquired ----------------------------------- or Placed Gas NGL Production into Throughput Throughput Throughput Plant Facilities Location Service Capacity (Mcfd) (Gal/Year) ------------------------------ ----------------- --------- ------------- ---------- -------------- Boldman Extraction Plant (1) Pike County, KY 1991 70,000 Mcfd 50,000 12,797,000 Cobb Extraction Plant (2) Kanawha County,WV 2000 35,000 Mcfd 27,000 19,747,000 Kenova Extraction Plant Wayne County, WV 1996 120,000 Mcfd 120,000 81,186,000 Kermit Dewpoint Control Plant Mingo County, WV 2001 39,000 Mcfd N/A N/A Maytown Extraction Plant (3) Floyd County, KY 2000 55,000 Mcfd 39,000 26,977,000 Siloam Fractionation Plant (4) South Shore, KY 1988 600,000 Gal/d N/A 148,082,000

Year Acquired Sales for the or Placed Throughput Storage Year Ended Storage and into Length in Capacity Capacity December 31, Transmission Facilities Location Service Miles (Gal/d) (Gal) 2000(Gal)(4) ------------------------------- ------------------- --------- --------- ---------- ---------- ------------- Siloam Fractionation Storage South Shore, KY 1988 N/A N/A 14,000,000 153,000,000 Terminal and Storage Lynchburg, VA 1999 N/A N/A 270,000 10,692,000 Terminal and Storage Church Hill, TN 1995 N/A N/A 240,000 3,822,000 Terminal and Storage Lordstown, OH 2000 N/A N/A 80,000 5,500,000 Kenova to Siloam pipeline Wayne County, WV 1988 38.5 831,000 N/A N/A to South Shore, KY Maytown to Kenova pipeline (5) Lincoln County to 2000 140.0 160,000 N/A N/A Wayne County, WV

(1) MarkWest assumed operations effective February 1, 2000. Previously, Boldman was leased to and operated by a third party. (2) Cobb was acquired March 1, 2000. Cobb was originally placed in service in 1968 and its extracted NGLs have historically been fractionated at Siloam. (3) Maytown was placed into service in February 2000. Maytown can be expanded to 75,000 Mcfd for a modest amount of capital. (4) Includes fractionation of NGLs extracted at Kenova, Boldman, Cobb and Maytown listed above. (5) A portion of the pipeline is leased from a third party. The Company's Appalachian operations are in the midst of a sizable expansion, growing production from 310,000 gallons per day in 1999 to 550,000 gallons per day by mid-2001. Production for 2000 was 405,000 gallons per day. See SIGNIFICANT 2000 AND 2001 DEVELOPMENTS earlier in this section for further information. The Company believes this region has favorable supply and demand characteristics. Appalachia is geographically situated between the TET pipeline to the north and the Dixie pipeline to the south. The historical demand for NGL products in Appalachia has exceeded local production and the capacity of these two lines during peak winter periods. This factor has enabled NGL suppliers in Appalachia (principally MarkWest, Marathon Ashland Petroleum LLC and CNG Transmission Corporation) to price their products (particularly propane) at a premium to Gulf Coast spot prices, especially during winter high demand periods. There are approximately 11,000 wells behind the Company's NGL extraction plants in Appalachia, with a potential for producers to drill up to another 20,000 to 50,000 infill wells. Typical wells in this area have long-lived reserves and modest decline rates. This 5 producing basin is one of the country's oldest, but is still one of the most prolific. The growth in production drilling can be attributed to the recently higher gas prices in an area close to the high-demand northeast U.S., improved drilling technologies, and cost reductions, all of which add up to improved economic returns for producers. The Kenova, Boldman, Cobb, Maytown and Kermit plants extract liquids from natural gas for further separation at the Company's Siloam fractionator. All of the NGLs recovered at the Kenova, Maytown and Boldman plants-beginning February 2000, Boldman NGLs are transported to Maytown via tanker trucks-are sent to Siloam via pipeline. Cobb and Kermit liquids are transported to Siloam via tanker trucks. At the Company's Siloam fractionation plant, extracted NGLs are separated into NGL products, including propane, isobutane, normal butane and natural gasoline. In addition to processing and NGL marketing, the Company engages in terminaling and storage of NGLs in a number of NGL storage complexes in the central and eastern United States and owns and operates propane terminals in Virginia, Tennessee and Ohio. MarkWest has contracted with producers for the exclusive right to process the producers' hydrocarbon-rich gas currently delivered into producer-owned and Columbia-owned transmission pipelines upstream of the Company's plants under long term contracts. MarkWest also has long term operating agreements with Columbia. The Company currently processes natural gas under contracts containing both keep-whole and fee components. In keep-whole arrangements, the Company's principal cost is the reimbursement to the natural gas producers for the Btus extracted from the gas stream in the form of liquids or consumed as fuel during processing. In such cases, the Company creates operating margins by maximizing the value of the NGLs extracted from the natural gas stream and minimizing the cost of replacement Btus. While the Company maintains programs to minimize the cost to deliver the replacement Btus to the natural gas supplier, the Company's margins under keep-whole contracts can be negatively affected by either decreases in NGL prices or increases in prices of replacement natural gas-See SIGNIFICANT 2000 AND 2001 DEVELOPMENTS above and ITEM 3 - LEGAL PROCEEDINGS. Processing contracts with producers also contain a fee component under which the producers pay MarkWest a fee to process their gas and provide a portion of their gas for fuel. The fee may be a per unit of throughput charge or a percentage of the resulting NGL sales ("percent-of-proceeds") or some combination of both. Substantially all of the Company's fractionation services in Appalachia historically have been provided under keep-whole contracts. The contract for processing services at the new Maytown plant contains fee and percent-of-proceeds components. The Company attempts to maximize the value of its NGL output by marketing directly to distributors, resellers, blenders, refiners and petrochemical companies. The Company minimizes the use of third-party brokers and instead supports a direct marketing staff focused on multistate and independent dealers. Additionally, the Company uses its own trailer and railcar fleet, as well as its own terminals and owned and leased storage facilities, to enhance supply reliability to its customers. All of these efforts have allowed the Company to maintain premium pricing for the majority of its NGL products compared to Gulf Coast spot prices. The Company's sales of NGLs are based on spot prices at the time the NGLs are sold or are hedged. Spot market prices are based upon prices and volumes negotiated for short terms, typically 30 days. As market conditions permit, the Company has increased its hedging activities as described in Note 7, COMMODITY PRICE RISK MANAGEMENT, in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. Historically, the majority of the Company's operating income has been derived from gathering, processing and marketing services in Appalachia. Revenues from the sale of Appalachian NGLs represented 54 percent, 52 percent, and 70 percent of gathering, processing and marketing revenues for the years ended December 31, 2000, 1999, and 1998, respectively. In 1998, the Company started a natural gas marketing group to provide, primarily in Appalachia, more services to natural gas producers, source new gas for the Company's facilities, minimize its replacement Btu cost, and assist with its business development efforts. The Company's natural gas marketing activities are fundamentally high volume, low margin transactions executed in support of MarkWest's processing business. Consequently, an increasing percentage of the Company's overall revenues stem from gas marketing. For the years ended December 31, 2000, 1999, and 1998, 41 percent, 32 percent, and 9 percent, respectively, of gathering, processing and marketing revenue stemmed from gas marketing. 6 MICHIGAN Certain information concerning the Company's Michigan assets is summarized in the following table:

For the Year Ended Year December 31, 2000 Acquired ----------------------------- or Placed Throughput Gas NGL Production into Capacity Throughput Throughput Facilities Location Service (Mcfd) (Mcfd) (Gal/Year) -------------------------- ------------------- --------- ---------- ---------- -------------- 90-mile sour gas gathering Manistee, Mason and 1996 (1) 35,000 11,000 N/A pipeline Oceana Counties, MI Fisk Gas Plant Manistee County, MI 1998 35,000 11,000 9,200,000

(1) Extended from 31 miles in 1996 to 63 miles in 1997 and 90 miles in 1998. The Company's operations in western Michigan consist of a pipeline and processing plant. The Company's gas gathering pipeline gathers and transports sour gas to a treatment plant, used to remove sulfur, owned and operated by a third party. MarkWest's Fisk processing plant is located adjacent to the third party's treating plant. The Fisk plant processes all of the natural gas gathered by the pipeline and treated by the third party's treating plant, producing propane and other liquid products. The plant also conditions the residue gas such that it can be sold directly into the Michigan Consolidated Gas Company dry distribution system serving western Michigan. The Company currently processes natural gas in western Michigan under contracts containing both fee and percent-of-proceeds components. The processing contracts with producers contain a fee component under which the producers pay MarkWest a fee to transport and treat their gas. Under the percent-of-proceeds component, the Company retains a portion of the NGLs as compensation for the processing services provided. Operating revenues earned by the Company under percent-of-proceeds contracts increase proportionately with the price of NGLs sold. The Company generally sells its propane production as soon as it is produced. The Company's butane- natural gasoline production is transported across the state via tanker trucks to the Marysville Fractionator, where it is separated into NGL products, including isobutane, normal butane and natural gasoline. Throughput volumes in western Michigan for 2000 were 11,000 Mcfd, down 38 percent compared to 1999 volumes. New drilling is critical to maintaining and increasing volumes. Drilling activity in the next few years will determine the sustainable production level for the project. MarkWest's own exploration efforts in 2000, along with partners, resulted in 4 dry holes. MarkWest's net interest in these 4 wells averaged 25 percent. However, litigation surrounding a third-party shut-in well is nearly settled, which is expected to allow for connection to MarkWest's system in the first or second quarter 2001. Another large producer well is expected to be on- stream in the fourth quarter. Last year volumes averaged 11,000 Mcfd. In 2001, average volumes are expected to be flat, although volumes are expected to ramp-up near year-end to 14,000 Mcfd. MarkWest has exclusive gathering, treatment and processing agreements with certain producers. Expected natural gas streams dedicated under these agreements will primarily be produced from an extension of the Northern Niagaran Reef trend in western Michigan. To date, over 2.5 trillion cubic feet equivalent of natural gas has been produced from the Northern Niagaran Reef trend. Substantially all of the natural gas produced from the western region of this trend, however, is sour. In the past, while several successful large wells were developed in the region, the natural gas producers lacked adequate gathering and treatment facilities for sour gas, and development of the trend stopped in northern Manistee County. However, with the Company's expanded infrastructure of the sour gas pipeline, treatment and processing facilities and increased capacity, the Company believes there could continue to be increased development in the region. In addition, the Company believes that improvements in seismic technology may increase exploration and production efforts, as well as drilling success rates. EXPLORATION AND PRODUCTION RESERVES Cawley, Gillespie & Associates, Inc., an independent reservoir engineer, has reviewed MarkWest's estimates of proved reserves, projected future production and estimated future net revenues from production of proved reserves. The estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by or available to the Company. 7 Proved reserves at year-end 2000 were 35 Bcf of natural gas compared to 33 Bcf at year-end 1999. The SEC pre-tax net present value of the proved reserves at year end 2000, discounted at 10 percent, was $98.0 million compared to $16.1 million reported at year-end 1999. Reserve values were calculated according to SEC guidelines based on constant prices and costs using year-end NYMEX Henry Hub spot market index of $9.52 per mmbtu adjusted to El Paso/ San Juan index of $8.56 per Mcf for 2000 and $2.32 per mmbtu and $2.30 per Mcf, respectively for 1999, adjusted for price hedges. As a sensitivity analysis MarkWest also evaluated its reserves based on an assumed El Paso/San Juan index price of $3.75 per Mcf, with prices and costs held constant. In this analysis, the pre-tax net present value of the reserves would have been approximately $37.4 million. Reserve additions from all sources during 2000 (excluding production and sales) amounted to 3.7 million Bcf. To accomplish uniformity in the reporting of reserves for comparison purposes, the SEC requires that the pre-tax PV 10 of future net revenues be calculated using a spot year-end pricing and costs, with no future escalation of these factors. Because these assumptions are not intended to be predictions of future commodity prices or costs, the calculated values are not intended to be indicative of the market value of these assets. The alternative analysis of the pre-tax PV 10 of future net revenues is presented above for comparative purposes only, and is not intended to represent the Company's estimate of future prices or the market value of these assets. There are uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company's control. The reserve data presented represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement. Estimates made by different engineers often vary from one another. Additionally, results of drilling, testing and production subsequent to the date of any estimate may justify revision of the estimate, either upward or downward, and such revision may be material. Accordingly, reserve estimates often differ from the quantities of gas reserves and the present value of those reserves are based upon certain assumptions, including prices, future production levels and cost, that may not prove correct over time. See related information in NOTE 15, SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES. ROCKY MOUNTAINS MarkWest has focused its exploration and production business in Rocky Mountain coal seam natural gas development-primarily in the San Juan Basin. In 2000, nearly $1.8 million was spent, primarily in the fourth quarter, on high-return workover activities on company properties to improve production. During the second quarter, 2000, MarkWest sold its interest in a non-core property for $350,000. Net natural gas sold for the year averaged 3,300 Mcfd, up 21 percent over the prior year. This increase reflects the benefit from higher production and the benefit realized from the 2000 capital program. In January 2001, the acquisition of additional coal bed methane properties and gathering systems in New Mexico's San Juan Basin added another 1,200 Mcfd of production. This acquisition along with our 2001 capital expenditure program of $ 4.0 million, is expected to increase our year-end 2001 production exit rate to more than 6,800 Mcfd. MICHIGAN In eastern Michigan, the Company contracted with a producer to provide gas processing services for a long-dormant sour gas formation. MarkWest also has a 25 percent working interest in the field. In the first phase of the project, completed in third quarter 2000, MarkWest has successfully recompleted the Sims 1-7 well, constructed a well facility, modified an existing gas plant and constructed a pipeline to bring an existing well into production from this formation. This well is producing 2,000 Mcfd. The second phase of the project is expected to begin in 2001 and will involve bringing another three to four wells into production and constructing additional processing facilities. Prior to the Sims 1-7, these wells have never produced from this formation due to the lack of infrastructure. Initial results look positive and could lead to significant additional investment in the project. Management believes the project has the potential to grow into a significant contributor to MarkWest. SEASONALITY A substantial portion of the Company's revenues and, as a result, its gross margins, remains dependent upon the sales price of NGLs, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants. The strongest demand for propane and the highest propane sales margins generally occur during the winter heating season. As a result, the Company recognizes a substantial portion of its annual income during the first and fourth quarters of the year. Specifically, this seasonality occurs in the Company's gathering, processing and marketing segment. 8 COMPETITION The Company faces competition in obtaining natural gas supplies for its processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing its products and services. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and ability to obtain a satisfactory price for products recovered. Competitive factors affecting the Company's fractionation services include availability of capacity, proximity to supply and to industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships. The Company's principal competitors include major integrated oil and gas companies, major interstate pipeline companies, national and local gas gatherers, NGL processing companies, brokers, marketers and distributors of varying sizes, financial resources and experience. Many of the Company's competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than that of the Company. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. Drilling activity behind the Company's systems varies with industry conditions, commodity prices, and effectively competes for capital with producers' other drilling opportunities. In the exploration and production segment, the Company faces competition in the acquisition of leases and producing properties. Competition comes in the form of other companies with existing operations in the Company's areas of focus as well as those companies wishing to buy properties as an entry strategy into such areas. Competitors range in size from small independent operators to large integrated oil companies. The Company believes it enjoys certain competitive advantages by virtue of its area knowledge and existing field operating infrastructure, making it a logical buyer for certain properties. OPERATIONAL RISKS AND INSURANCE The Company's operations are subject to the usual hazards incident to the exploration for and production, gathering, transmission, processing and storage of natural gas and NGLs, such as explosions, product spills, leaks, emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility. The Company maintains general public liability, property and business interruption insurance in amounts that it considers to be adequate for such risks. Such insurance is subject to deductibles that the Company considers reasonable and not excessive. Consistent with insurance coverage generally available to the industry, the Company's insurance policies provide coverage for losses or liabilities related to sudden occurrences of pollution or other environmental damage. The occurrence of a significant event not fully insured or indemnified against, and/or the failure of a party to meet its indemnification obligations, could materially and adversely affect the Company's operations and financial condition. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable. To date, however, the Company has experienced no material uninsured losses or any difficulty in acquiring insurance coverage in amounts it believes to be adequate. GOVERNMENT REGULATION In the Michigan area of the gathering, processing and marketing segment, the Company owns and operates a gathering pipeline in conjunction with its processing plant. Under the Natural Gas Act of 1938, facilities that have as their "primary function" the performance of gathering activities and are not owned by interstate gas pipeline companies are wholly exempt from Federal Energy Regulatory Commission jurisdiction. State and local regulatory authorities oversee intrastate gathering and other natural gas pipeline operations. The Michigan Public Service Commission ("MPSC") regulates the construction, operation, rates and safety of certain natural gas gathering and transmission pipelines pursuant to state regulatory statutes. The Company conducts gas pipeline operations in Michigan through an affiliate, which is subject to this regulation by the MPSC. The design, construction, operation and maintenance of the Company's pipeline are also subject to safety regulations. Natural gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. The effect of these regulations may limit the amount of gas available to the Company's systems or which the Company can produce from its wells. They also substantially affect the cost and profitability of conducting natural gas exploration and production activities. 9 ENVIRONMENTAL MATTERS The Company is subject to environmental risks normally incident to its operations and construction activities including, but not limited to, uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution, and other environmental and safety risks. The following is not intended to constitute a complete discussion of the various federal, state and local statutes, rules, regulations, or orders to which the Company's operations may be subject. For example, the Company, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as the "Superfund" law), or state counterparts, in connection with the disposal or other releases of hazardous substances, including sour gas, and for natural resource damages. Further, the recent trend in environmental legislation and regulations is toward stricter standards, and this will likely continue in the future. The Company's activities are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the federal Environmental Protection Agency, which can increase the costs of designing, installing and operating its facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution. Laws and regulations may require a permit or other authorization before certain activities may be conducted by the Company and include fines and penalties for non-compliance. Further, these rules may limit or prohibit activities within wilderness areas, wetlands, and areas providing habitat for certain species or other protected areas. The Company is also subject to other federal, state and local laws covering the handling, storage or discharge of materials used by the Company. The Company believes that it is in material compliance with all applicable laws and regulations. EMPLOYEES As of December 31, 2000, the Company had 122 employees. Fourteen employees at the Company's Siloam fractionation facility in South Shore, Kentucky, are represented by the Paper, Allied Industrial, Chemical, and Energy Workers International Union Local 5-0372. The Company's collective bargaining agreement with this Union expired on April 30, 2000; new contract negotiations continue. The agreement covered only hourly, non- supervisory employees. The Company considers labor relations to be satisfactory at this time. FORWARD-LOOKING INFORMATION This Annual Report on Form 10-K contains statements which, to the extent that they are not recitations of historical fact, constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, ("Section 27A") and Section 21E of the Securities and Exchange Act of 1934, as amended, ("Section 21E") including statements with respect to the outcome of the pending litigation matters and contract negotiations. All forward-looking statements involve risks and uncertainties. The forward-looking statements in this document are intended to be subject to the safe harbor protection provided by Sections 27A and 21E. Factors that most typically impact MarkWest's operating results and financial condition include: (i) changes in general economic conditions in regions in which the Company's products are located; (ii) the availability and prices of NGL and competing commodities; (iii) the availability and prices of raw natural gas supply; (iv) the ability of the Company to negotiate favorable marketing agreements; (v) the risks that third party or Company natural gas exploration and production activities will not occur or be successful; (vi) the Company's dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas; (vii) competition from other NGL processors, including major energy companies; (viii) the Company's ability to identify and consummate grass roots projects or acquisitions complementary to its business; (ix) winter weather conditions; and (x) intermediate or final decisions in the pending litigation, and the relative positions of the parties in the negotiation of new agreements. Forward-looking statements involve many uncertainties that are beyond the Company's ability to control and in many cases the Company cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements. ITEM 3. LEGAL PROCEEDINGS As the Company reported in a current report on Form 8-K , dated February 22, 2001, three complaints have been filed against it in the Circuit Court of Wayne County, West Virginia, by Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy LLC; and Cobra Petroleum Production Company et al. These complaints each allege breach of contract and seek various forms of relief (including injunctive relief) and damages. Current and futures prices for natural gas have risen dramatically, and prices for natural gas liquids ("NGLs") (propane, butane, etc.) have stayed essentially flat. A large portion of MarkWest's processing services for gas producers in Appalachia involves extracting 10 NGLs from inlet gas streams and replacing the equivalent heat content with dry natural gas purchased in the spot or forward markets. This part of the Company's operating margin depends on a positive spread between NGL prices and natural gas costs. When feasible, the Company has hedged a substantial portion of its natural gas redelivery obligation. Effective February 1, 2001, the Company provided producers with an alternative processing contract that provides for additional compensation when processing margins are low and reduced compensation when these margins are high. To date, about 65 producers (accounting for a minority share of the volume) out of approximately 325 have agreed to the new contract. If producers elect to remain with the existing contract, the Company has stated it will return the replacement natural gas at a later date as it believes is permitted under the existing contract such that the Company can earn a reasonable fee for its services. The complaints allege this procedure for the existing contracts constitutes a breach. The parties have agreed to a temporary standstill to the litigation and are currently negotiating a resolution to this dispute. There can be no assurance that these negotiations will be successful or that the outcome of the litigation or the settlement discussions will be favorable to the Company. These high natural gas price conditions, of course, are not an isolated situation with MarkWest-nationwide, producers and gas processors are renegotiating their processing agreements for this reason. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the quarter ended December 31, 2000. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The American Stock Exchange began trading shares of MarkWest Hydrocarbon, Inc. under the ticker symbol MWP on Friday, May 12, 2000. The Company's stock formerly traded on the American Stock Exchange under the ticker symbol NRG through May 11, 2000. As of December 31, 2000, there were 8,561,206 shares of common stock outstanding held by approximately 600 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange for the periods indicated.

2000 1999 ------------------ --------------- HIGH LOW HIGH LOW ------ ------ ------ ---- First Quarter ...... 6.921 6.743 9.250 5.75 Second Quarter ..... 8.432 8.230 11.375 7.00 Third Quarter ...... 8.869 8.688 8.875 5.00 Fourth Quarter ..... 11.705 11.498 7.875 4.75

The Company has paid no dividends on the common stock and anticipates that, for the foreseeable future, it will continue to retain earnings for use in the operation of its business. Payment of cash dividends in the future will depend upon the Company's earnings; financial condition; contractual restrictions, if any, including those under its bank line of credit; restrictions imposed by law and other factors deemed relevant by the Company's Board of Directors. 11 ITEM 6. SELECTED FINANCIAL DATA The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2000, 1999, and 1998, and as of December 31, 2000, and 1999, are derived from, and are qualified by reference to, audited consolidated financial statements of the Company included elsewhere in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below for the years ended December 31, 1997 and 1996, and as of December 31, 1997 and 1996, have been derived from audited financial statements not included in this Form 10-K. The selected consolidated financial information set forth below should be read in conjunction with Item 7 - Management's Discussions and Analysis of Financial Condition and Results of Operations and the Company's Consolidated Financial Statements and related notes thereto included in this Form 10-K.

Year Ended December 31, ------------------------------------------------------------------------------ 2000 1999 1998 1997 1996 ------------- ------------- ------------- ------------- ------------- (in thousands, except per share amounts and operating data) STATEMENT OF OPERATIONS: Revenues (1) ................................ $ 221,554 $ 107,010 $ 64,605 $ 79,714 $ 71,449 Cost of sales ............................... 173,281 77,314 43,866 46,545 41,594 Operating expenses .......................... 17,339 12,657 10,785 11,286 7,597 Cash operating margin (2) ................... 30,934 17,039 9,954 21,883 22,258 General and administrative expenses ......... 8,761 6,986 5,319 6,651 4,753 Depreciation, depletion and amortization .... 6,314 5,070 4,594 3,246 2,910 Income from operations ...................... 15,859 4,983 41 11,986 14,595 Net income (loss) (3), (4) .................. 8,878 2,823 (1,211) 7,847 7,769 Basic earnings per share (3), (4), (5) ...... 1.05 0.33 (0.14) 0.92 1.21 Earnings per share assuming dilution (3), (4), (5) ................... $ 1.05 $ 0.33 $ (0.14) $ 0.91 $ 1.20 Weighted average shares outstanding (6) .......................... 8,452 8,475 8,490 8,485 6,415 assuming dilution (6) .................... 8,492 8,481 8,490 8,614 6,481 CASH FLOW DATA: Cash flows from operating activities, before working capital changes ........... $ 17,259 $ 6,393 $ 4,795 $ 12,650 $ 14,702 Capital and acquisition expenditures ........ $ 18,765 $ 17,898 $ 15,890 $ 30,329 $ 17,516 OTHER FINANCIAL DATA: EBITDA (7) .................................. $ 22,089 $ 9,777 $ 4,511 $ 15,808 $ 18,568 BALANCE SHEET DATA (AS OF DECEMBER 31): Working capital (8) ......................... $ 15,148 $ 11,511 $ 11,463 $ 14,603 $ 11,896 Property and equipment, gross ............... 128,052 115,100 102,931 81,269 60,456 Property and equipment, net ................. 100,219 92,311 83,322 65,830 48,140 Total assets ................................ 147,287 119,243 103,631 98,657 78,254 Long-term debt .............................. 43,000 44,035 38,597 33,931 11,257 Stockholders' equity ........................ $ 61,594 $ 52,719 $ 50,035 $ 51,548 $ 43,664

12

Year Ended December 31, ------------------------------------------------------------------------------ 2000 1999 1998 1997 1996 ------------- ------------- ------------- ------------- ------------- OPERATING DATA GATHERING, PROCESSING AND MARKETING Appalachia: NGL production--Siloam plant (gallons) ... 148,100,000 113,000,000 102,900,000 102,500,000 94,900,000 NGL sales--Siloam plant (gallons) ........ 153,000,000 115,800,000 100,900,000 103,400,000 94,600,000 Michigan:(9) Pipeline throughput (Mcfd) ............... 11,000 17,800 16,000 8,900 4,800 NGL sales (gallons) ...................... 9,200,000 13,500,000 10,600,000 -- -- EXPLORATION AND PRODUCTION Natural gas produced (Mcfd) .............. 3,800 2,500 1,900 1,400 700

------------ (1) Includes gas marketing revenues of $89,700, $34,100 and $5,600 for the years ended December 31, 2000, 1999 and 1998, respectively. The Company's gas marketing business originated in 1998. Gas marketing activities are low margin; these activities are done in support of MarkWest's processing business. (2) Includes gathering, processing, and marketing revenue; oil and gas revenue; cost of sales; and operating expenses. (3) In 2000, includes $1,000 gain ($620, or $0.07 per share, after-tax) from the sale of an asset. (4) In 1999, includes $2,509 gain ($1,566, or $0.18 per share, after-tax) from the sale of an asset. (5) Prior to October 7, 1996, the Company was organized as a partnership-MarkWest Hydrocarbon Partners, Ltd. ("MarkWest Partnership")-and consequently, was not subject to income tax. Effective October 7, 1996, the Company reorganized (the "Reorganization"), and the existing general and limited partners exchanged 100 percent of their interests in MarkWest Partnership for 5,725,000 common shares of the Company. Pro forma information has been presented for purposes of comparability as if the Company had been a taxable entity for all periods presented:

Year Ended December 31, 1996 -------------------------------------------------------------------- Historical income before income taxes ................. $14,760 Pro forma provision for income taxes .................. 5,609 Pro forma net income .................................. 9,151 Pro forma basic earnings per share .................... 1.16 Pro forma earnings per share assuming dilution ........ $ 1.15 Pro forma weighted average shares outstanding (a) ..... 7,908

(a) Pro forma weighted average shares outstanding represents the weighted average of, for the period prior to the initial public offering (the "Offering"), the number of common shares issued in the Reorganization plus the number of shares issued in the Offering for which the net proceeds were used to repay outstanding indebtedness and, for the period subsequent to the Offering, the total number of common shares outstanding. (6) Weighted average shares outstanding for the year ended December 31, 1996, represents the weighted average of, for the period prior to the Company's initial public offering, the number of common shares issued in the Reorganization and, for the period subsequent to the Offering, the total number of common shares outstanding. (7) Earnings (loss) before interest income; interest expense; income taxes; depreciation, depletion, and amortization; and gain on sale of West Memphis terminal and ticker symbol. (8) Includes cash of $934; $1,356; $2,055; $1,364; and $4,401, respectively. (9) 2000, 1999, 1998 and 1997 results reflect the Company's acquisition of the remaining 40 percent interest of the Michigan operations in November 1997. Prior to November 1997, MarkWest owned 60 percent of the Michigan operations. Pipeline operations commenced in 1996; the Fisk processing plant commenced operations in 1998. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following analysis should be read in conjunction with Item 6 - Selected Financial Data and the Company's Consolidated Financial Statements included in this Form 10-K. RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2000, COMPARED TO YEAR ENDED DECEMBER 31, 1999 OVERVIEW For the year ended December 31, 2000, net income was $8.9 million, or $1.05 per share, up $6.1 million or $0.72 per share from 1999. Excluding gains on asset sales in both periods, income was $8.3 million, or $0.97 per share, for the year ended December 31, 13 2000 compared to a net income of $1.3 million, or $0.15 per share, for the prior year. EBITDA was $22.1 million for the year ended December 31, 2000, compared to $9.8 million for the year ended December 31, 1999. Results for the year ended December 31, 2000, were significantly impacted by the record NGL production and sales volumes in the gathering, processing and marketing segment. The increased volumes are due to increased gas production behind the company's facilities, gas extraction and fractionator plant expansions and additional marketing terminals in the Appalachia area. Decreased western Michigan throughput and sales volume were partially offset by higher NGL prices. Natural gas production in the Exploration and Production segment also positively impacted results for the year ended December 31, 2000. Daily production, net to MarkWest interest was 3,800 thousand cubic feet (mcf) per day for 2000, a 52 percent increase over 1999 production levels. For the year ended December 31, 2000, the Company expected increases in operating, general and administrative, depreciation and interest expenses. These increases were due to the Company's Appalachia expansion program. GATHERING, PROCESSING AND MARKETING REVENUE MarkWest is paid for its processing services in Appalachia through sales of liquids extracted and fees for units of throughput. Recent sales volumes of liquids at the Company's Siloam, Kentucky, fractionation facility were a record 153 million gallons compared to 116 million gallons for 1999, a 32 percent increase. Higher prices and increased volumes at the terminals also benefited revenues. For the year ended December 31, 2000, gas marketing revenue was $90.0 million compared to $34.0 million for the year ended December 31, 1999. The natural gas marketing activities are high volume, low margin transactions supporting MarkWest's processing business. In western Michigan, volumes were 11,000 Mcfd for the year ended December 31, 2000 compared to 17,800 Mcfd for the year ended December 31, 1999. This decline was partially offset by higher NGL prices. EXPLORATION AND PRODUCTION REVENUE Natural gas sold during the year ended December 31, 2000 totaled 3,800 Mcfd-a 52 percent increase over the 2,500 Mcfd produced and sold during the year ended December 31, 1999. Production has increased because of the Company's capital program. COSTS AND EXPENSES COST OF SALES. Cost of sales for the year ended December 31, 2000 increased $96 million or 124 percent compared to the year ended December 31, 1999. Similarly, sales increased by nearly 110 percent from 1999 to 2000. The Company's replacement feedstock in Appalachia increased $21 million as a result of increased volumes and unit costs. In addition, the cost of sales for natural gas marketing increased $55 million due to the increased volumes. Combined with a corresponding increase in gas marketing sales, the 2000 gross margin from gas marketing increased $0.3 million compared to 1999. The natural gas marketing activities generate low margins; these activities are executed in support of MarkWest's processing business. The cost and volume increases at the Company's Appalachian terminals and Michigan facilities increased cost of sales by $20 million. OPERATING EXPENSES. Operating expenses increased $4.7 million or 37 percent for the year ended December 31, 2000 compared to the year ended December 31, 1999. The increase is primarily attributable to operating costs associated with incremental facilities added in Appalachia since third quarter 1999: the Lynchburg and Lordstown terminals; the Maytown, Boldman and Cobb extraction facilities and related pipeline; and the expanded Siloam fractionation plant. Higher natural gas costs in 2000 also impacted fuel costs at its plants. Finally, increased costs to achieve increased natural gas production were realized in MarkWest's exploration and production segment. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased $1.8 million or 25 percent primarily in support of the additional and expanded Appalachia facilities previously mentioned and rent for office space; the Company sold its corporate headquarters and leased back its office space commencing in February 2000. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization increased for the year ended December 31, 2000 as a result of the completion of the Phase I expansion in Appalachia in the first quarter of 2000. 14 YEAR ENDED DECEMBER 31, 1999, COMPARED TO YEAR ENDED DECEMBER 31, 1998 OVERVIEW For the year ended December 31, 1999, MarkWest reported net income of $2.8 million, or $0.33 per share, a $4.0 million increase in net income over 1998's net loss of $1.2 million, or $0.14 per share. Aside from the Company's $1.5 million, or $0.18 per share, after-tax gain on the sale of the Company's West Memphis terminal, record NGL production and sales in Appalachia, coupled with improving Appalachian processing margins in the Company's gathering, processing and marketing segment, were the primary reasons behind the Company's return to profitability in 1999. MarkWest sold 115.8 million gallons of NGLs in 1999, a 15 percent increase over 1998 levels, as gas production increased behind the Company's facilities. Although Appalachian processing margins were up over 1998, they were still significantly below the Company's ten-year historical average. Increased NGL prices contributed to improving margins. Increased profitability from MarkWest's terminals, due to increased NGL sales prices, and Michigan operations, due to increased throughput and NGL sales prices, also contributed in 1999. Expected increases in operating, general and administrative, interest and depreciation, depletion and amortization expenses occurred. GATHERING, PROCESSING AND MARKETING REVENUE Gathering, processing and marketing revenue increased $42.0 million, or 66 percent, for the year ended December 31, 1999, compared to the year ended December 31, 1998. The revenue increase was principally attributable to a $28.5 million increase in the Company's gas marketing operations. At the Company's Siloam fractionation facility, higher NGL sales prices and larger volumes of NGLs marketed contributed to increased 1999 revenues. EXPLORATION AND PRODUCTION REVENUE Oil and gas revenue increased $0.5 million for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase was primarily attributable to an increase in gas production from the prior year. COSTS AND EXPENSES COST OF SALES. Cost of sales increased $33.5 million, or 76 percent, for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase was primarily caused by a $28.5 million increase in gas marketing purchases. At the Company's Siloam fractionation facility, both higher natural gas costs and larger volumes of natural gas purchased contributed to increased 1999 cost of sales. OPERATING EXPENSES. Operating expenses increased $1.9 million, or 17 percent, for the year ended December 31, 1999, compared to the year ended December 31, 1998. The increase in operating expenses was principally attributable to four factors. First, certain expenses increased with volumes in Appalachia, Michigan and the Rocky Mountains. Second, MarkWest sold and leased back three compressors at its Kenova processing plant beginning in the third quarter of 1998. Consequently, 1999 operating expenses include twelve full months of lease expense whereas the results from the comparable time period in 1998 do not. Further, these compressors were overhauled in 1999. Third, 1998 operating expenses were lower due to a sales and use tax refund during that period. Last, performance-based incentive compensation increased in 1999; MarkWest did not pay bonuses in 1998 due to the Company's overall net loss. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased $1.7 million, or 31 percent, for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase is attributable to increased performance-based incentive compensation (MarkWest did not pay incentive bonuses in 1998 due to the Company's overall net loss); professional service fees also increased in 1999 due to the Company's arbitration with Columbia, now settled; and to increased business development expenditures. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization increased $0.5 million, or 10 percent, for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase was principally due to the Company's pipeline extension in Michigan placed in service during mid-1998. INTEREST EXPENSE. Interest expense increased $0.7 million for the year ended December 31, 1999, compared to the year ended December 31, 1998, due to increased average outstanding debt and higher interest rates. 15 LIQUIDITY AND CAPITAL RESOURCES The Company's sources of liquidity and capital resources historically have been internal cash flow and its revolving line of credit. In the first quarter of 2000, these sources were supplemented by proceeds from the sale of the Company's corporate office building. In the second quarter of 2000, MarkWest increased its line of credit by $15 million to $65 million. The following summary table reflects comparative cash flows for the Company for the three years ended December 31 (in 000's):

2000 1999 1998 -------- -------- -------- Net cash provided by operating activities before change in working capital ....................................................... $ 17,259 $ 6,393 $ 4,795 Net cash provided by (used in) operating activities from change in working capital .. (3,924) (253) 3,638 Net cash provided by (used in) investing activities (1) ............................. (12,273) (11,884) (11,559) Net cash provided by (used in) financing activities ................................. $ (1,484) $ 5,045 $ 3,817

(1) Net of asset sales of $6,492, $6,014 and $4,281, respectively. CAPITAL INVESTMENT PROGRAM Investing activities consist primarily of capital and acquisition expenditures net of asset sales. The Company's capital expenditures are summarized as follows (in millions):

For the Year Ended December 31, ------------------------------- 2000 1999 1998 ------- ------- ------- GATHERING, PROCESSING AND MARKETING Appalachia Phase I expansion ..................... $ 4.5 $ 9.3 $ -- Phase II expansion .................... 4.3 -- -- Marketing assets ...................... 3.4 2.1 -- Western Michigan Pipeline expansion .................... -- 0.1 10.7 Maintenance capital and other .................. 1.1 1.8 2.2 ------- ------- ------- Gathering, processing and marketing ... $ 13.3 $ 13.3 $ 12.9 ------- ------- ------- EXPLORATION AND PRODUCTION Rocky Mountains ................................ $ 2.6 $ 3.6 $ 2.9 Western Michigan ............................... 1.4 0.8 0.1 Eastern Michigan ............................... 1.5 0.2 -- ------- ------- ------- Exploration and production ............ 5.5 4.6 3.0 ------- ------- ------- Total capital expenditures ............ $ 18.8 $ 17.9 $ 15.9 ======= ======= =======

Looking ahead, MarkWest forecasts a baseline capital budget of $24.5 million in 2001: in its gathering, processing and marketing segment - $8 million for completion of Appalachia's Phase II expansion, $2.5 million for marketing infrastructure expansion and $1.5 million for maintenance capital; in its exploration and production segment - $5 million for the acquisition of San Juan Basin properties in January 2001, up to $4 million for infill drilling in the San Juan Basin and up to $3.5 million for further expansion of the Au Gres, Michigan property. These latter two expenditures are discretionary and could be reduced depending on capital availability. FINANCING FACILITIES Financing activities consist primarily of net borrowings under the Company's credit facility. At December 31, 2000, the Company had $65 million of available credit, of which net debt (debt less cash) of $42.1 million had been utilized, and working capital of $15.1 million. Depending on the timing and amount of the Company's future projects beyond the level described above, and the outcome of the Appalachia producer litigation and negotiations described in SIGNIFICANT 2000 AND 2001 DEVELOPMENTS in ITEMS 1 AND 2 - BUSINESS AND PROPERTIES and ITEM 3 - LEGAL PROCEEDINGS of this Form 10-K, MarkWest may be required to seek additional sources of 16 capital. While the Company believes that it will be able to secure additional financing on terms acceptable to the Company, if required, no assurance can be given that it will be able to do so. 2001 OUTLOOK In the gathering, processing and marketing segment, the Appalachia Phase II expansion is expected to add 90,000 gallons per day of NGL production beginning in the third quarter of 2001, with the expectation therefore that sales volumes of NGLs from the Siloam fractionator will be approximately 170 million gallons, up 10 percent from 2000. Michigan natural gas volumes transported and processed are expected to be flat at approximately 11,000 Mcfd based on resolution in the first quarter 2001 of third party litigation on several wells and hook up of a new well by the fourth quarter 2001. As a result of these additions, the year end flow rate is expected to be about 14,000 Mcfd. As the Company reported in a current report on Form 8-K date February 22, 2001, current and futures prices for natural gas have risen dramatically, and prices for NGLs (propane, butane, etc.) have stayed essentially flat. A large portion, about 75 percent, of MarkWest's processing services for gas producers in Appalachia involves extracting NGLs from inlet gas streams and replacing the equivalent heat content with dry natural gas purchased in the spot or forward markets. This part of the Company's operating margin depends on a positive spread between NGL prices and natural gas costs. (However, when feasible, the Company hedges a portion of this processing margin - for example, as of February 27, 2001, the Company had hedged 17.4 million gallons for 2001 at a margin of $0.22 per gallon.) Effective February 1, 2001, the Company provided producers with an alternative processing contract that provides for additional compensation when processing margins are low and reduced compensation when these margins are high. To date, approximately 65 producers (accounting for a minority share of the volume) out of approximately 325 have agreed to the new contract. If producers elect to remain with the existing contract, the Company has stated it will return the replacement natural gas at a later date as it believes is permitted under the existing contract such that the Company can earn a reasonable fee for its services. See also ITEM 3 - LEGAL PROCEEDINGS of this Form 10-K. These high natural gas price conditions, of course, are not an isolated situation with MarkWest - nationwide, producers and gas processors are renegotiating their processing agreements for this reason. In the exploration and production segment, volumes produced are expected to increase over 100 percent to 8,000 Mcfd as a result of a January 2001 acquisition in the San Juan Basin, capital spending in the fourth quarter of 2000 and the full year 2001, startup of the first well in the Au Gres field in eastern Michigan in the third quarter of 2000, and the expected recompletion of a second Au Gres well in the first half of 2001. About 60 percent of the 2001 volumes have been hedged at a Henry Hub equivalent price of $3.85 per MMbtu. Other key expectations for 2001 include: operating costs of $20 million, up from $17 million in 2000 due to growth in Appalachia processing volumes and higher per unit fuel costs, and increased natural gas production; general and administrative expense of $9 million, unchanged from 2000; depreciation, depletion and amortization expense $7 million, up from 2000's $6.3 million as a result of capital expenditures; and a tax rate of 39 percent (one-third of which is current, the balance deferred). COMMODITY PRICE RISK MANAGEMENT ACTIVITIES Reference is made to Notes 7 and 8 of the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's hedging strategy limited the Company's after-tax earnings compared to the situation of not hedging. In the gathering, processing and marketing segment, net income would have been higher by $1.7 million, $0.9 million and $0 for the years ended December 31, 2000, 1999 and 1998, respectively. This impact considers only hedges of Appalachia processing margin and does reflect other decisions made concerning when to buy natural gas or store NGL production for sale in later months. In the exploration and production segment, without hedging, net income would have been higher by $0.6 million, $0.1 million and $0, respectively, for the years ended December 31, 2000, 1999 and 1998. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company faces market risk from commodity price variations, primarily in the NGLs it sells and in the natural gas it purchases. It also incurs, to a lesser extent, credit risks and risks related to interest rate variations. COMMODITY PRICE RISK. In the past, NGL prices and natural gas costs have fluctuated widely in response to changing market forces. The impacts of these price fluctuations on earnings from natural gas processing and natural gas production activities have been significant and have varied from year to year. The Company typically hedges a portion of its commodity price risk. Prior to hedging activities, MarkWest's Appalachian operations' cash flow has an annual sensitivity to NGL prices equal to $1.3 million in pretax income for every $0.01 per gallon change in NGL prices and an annual sensitivity to natural gas prices equal to $1.3 million 17 in pretax income for every $0.10 per MMBtu change in natural gas prices. For 2001, the Company has hedged approximately 13 percent of its Appalachian keep-whole volumes as of February 27, 2001, reducing the annual sensitivity accordingly. With the growth in the Company's exploration and production activities, the impact of variable natural gas prices on its revenues is increasing, which the Company mitigates through an extensive hedging program. As of February 27, 2001, the Company has hedged approximately 53 percent of its expected production for the year 2001. Accordingly, MarkWest's annual sensitivity to natural gas prices for 2001 is $0.1 million for each $0.10 per MMBtu change in natural gas prices. Gains and losses experienced on hedging transactions are generally offset by the related gains or losses on the sale of the underlying product in the physical market. See related discussion in Note 7 to the Company's Consolidated Financial Statements. CREDIT RISK. The Company is exposed to potential losses as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements, which facilitate the netting of cash flows associated with a single counterparty. The Company also monitors the financial condition of existing counterparties on an ongoing basis. INTEREST RATE RISK. The Company is exposed to changes in interest rates, primarily as a result of its long-term debt with floating interest rates. The Company may make use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, although no such agreements are currently in place. The impact of a 100 basis point increase in interest rates on the Company's debt would result in an increase in interest expense and a decrease in income before taxes of approximately $0.4 million. This amount has been determined by considering the impact of the hypothetical interest rates on the Company's variable-rate debt balances as of December 31, 2000. 18 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page ---- Report of Independent Accountants ......................................... 19 Consolidated Balance Sheet at December 31, 2000 and 1999 .................. 20 Consolidated Statement of Operations for each of the three years in the period ended December 31, 2000 .......................... 21 Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 2000 .......................... 22 Consolidated Statement of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 2000 .... 23 Notes to Consolidated Financial Statements ................................ 24

REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc. In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows and of changes in stockholders' equity present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Denver, Colorado February 7, 2001, except for Note 13(b), as to which the date is March 26, 2001 19 MARKWEST HYDROCARBON, INC. CONSOLIDATED BALANCE SHEET (000s, EXCEPT PER SHARE DATA)

December 31, ------------------------- 2000 1999 --------- --------- ASSETS Current assets: Cash and cash equivalents ............................................ $ 934 $ 1,356 Receivables .......................................................... 36,695 16,360 Inventories .......................................................... 8,058 6,043 Prepaid feedstock .................................................... -- 1,895 Other assets ......................................................... 913 327 --------- --------- Total current assets ........................................... 46,600 25,981 Property and equipment: Gas processing, gathering, storage and marketing equipment ........... 97,311 78,476 Oil and gas properties and equipment ................................. 18,037 14,518 Land, buildings and other equipment .................................. 6,463 11,409 Construction in progress ............................................. 6,241 10,697 --------- --------- 128,052 115,100 Less: accumulated depreciation, depletion and amortization ........... (27,833) (22,789) --------- --------- Total property and equipment, net .............................. 100,219 92,311 Intangible assets, net of accumulated amortization of $708 and $438, respectively .......................................... 468 951 --------- --------- Total assets ................................................... $ 147,287 $ 119,243 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable ..................................................... $ 17,713 $ 10,031 Accrued liabilities .................................................. 13,740 4,335 Current portion of long-term debt .................................... -- 104 --------- --------- Total current liabilities ...................................... 31,453 14,470 Deferred income taxes .................................................... 11,240 8,019 Long-term debt ........................................................... 43,000 44,035 Commitments and contingencies (see Note 13b) ............................. -- -- Stockholders' equity: Preferred stock, par value $0.01; 5,000,000 shares authorized, 0 shares outstanding................................... -- -- --------- --------- Common stock, par value $0.01; 20,000,000 shares authorized, 8,561,206 and 8,531,206 shares issued, respectively.... 86 85 Additional paid-in capital ........................................... 42,471 42,222 Retained earnings .................................................... 19,679 10,801 Treasury stock; 104,093 and 69,504 shares, respectively ............. (642) (389) --------- --------- Total stockholders' equity ..................................... 61,594 52,719 --------- --------- Total liabilities and stockholders' equity ..................... $ 147,287 $ 119,243 ========= =========

The accompanying notes are an integral part of these financial statements. 20 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF OPERATIONS (000s, EXCEPT PER SHARE DATA)

For the Year Ended December 31, ----------------------------------------- 2000 1999 1998 --------- --------- --------- Revenue: Gathering, processing and marketing revenue .................. $ 217,393 $ 105,150 $ 63,190 Exploration and production revenue ........................... 4,161 1,860 1,415 --------- --------- --------- Total revenues .................................... 221,554 107,010 64,605 --------- --------- --------- Operating expenses: Cost of sales ................................................ 173,281 77,314 43,866 Operating expenses ........................................... 17,339 12,657 10,785 General and administrative expenses .......................... 8,761 6,986 5,319 Depreciation, depletion and amortization ..................... 6,314 5,070 4,594 --------- --------- --------- Total operating expenses .......................... 205,695 102,027 64,564 --------- --------- --------- Income from operations ............................ 15,859 4,983 41 --------- --------- --------- Other income and expense: Interest income ............................................. 101 53 200 Interest expense ............................................ (3,110) (2,745) (2,095) Gain on sale of assets ...................................... 1,000 2,509 -- Other income (expense) ...................................... (84) (276) (124) --------- --------- --------- Income (loss) before income taxes ................. 13,766 4,524 (1,978) --------- --------- --------- Provision (benefit) for income taxes: Current ...................................................... 1,666 759 (2,235) Deferred ..................................................... 3,222 942 1,468 --------- --------- --------- Provision for income taxes ........................ 4,888 1,701 767 --------- --------- --------- Net income (loss) ................................. $ 8,878 $ 2,823 $ (1,211) ========= ========= ========= Basic earnings (loss) per share of common stock .................. $ 1.05 $ 0.33 $ (0.14) ========= ========= ========= Earnings (loss) per share assuming dilution ...................... $ 1.05 $ 0.33 $ (0.14) ========= ========= ========= Weighted average number of outstanding shares of common stock: Basic ............................................. 8,452 8,475 8,490 ========= ========= ========= Assuming dilution ................................. 8,492 8,481 8,490 ========= ========= =========

The accompanying notes are an integral part of these financial statements. 21 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (000s)

For the Year Ended December 31, -------------------------------------- 2000 1999 1998 -------- -------- -------- Cash flows from operating activities: Net income (loss) ..................................................... $ 8,878 $ 2,823 $ (1,211) Add income items that do not affect working capital: Depreciation, depletion and amortization .......................... 6,314 5,070 4,594 Deferred income taxes ............................................. 3,222 942 1,468 Gain on sale of assets ............................................ (1,000) (2,509) -- Other ............................................................. (155) 67 (56) -------- -------- -------- 17,259 6,393 4,795 Adjustments to working capital: (Increase) decrease in receivables ................................ (20,335) (8,622) 2,541 (Increase) decrease in inventories ................................ (2,015) (1,460) 558 (Increase) decrease in prepaid expenses and other assets .......... 1,301 2,787 379 Increase (decrease) in accounts payable and accrued liabilities ... 17,125 7,042 160 -------- -------- -------- (3,924) (253) 3,638 Net cash flow provided by operating activities ............. 13,335 6,140 8,433 Cash flows from investing activities: Capital expenditures .............................................. (18,765) (17,898) (15,890) Proceeds from sale/leaseback transaction .......................... -- -- 4,281 Proceeds from sale of assets ...................................... 6,492 6,014 -- Change in note receivable and other ............................... -- -- 50 -------- -------- -------- Net cash used in investing activities ...................... (12,273) (11,884) (11,559) Cash flows from financing activities: Proceeds from long-term debt ...................................... 55,000 48,056 39,200 Repayments of long-term debt ...................................... (56,139) (42,577) (34,627) Debt issuance costs ............................................... (342) (295) (454) Exercise of stock options ......................................... 38 -- -- Acquisition of treasury stock ..................................... (251) (1,035) (690) Reissuance of treasury stock ...................................... 210 896 296 Proceeds from exercise of options and payment on share purchase notes ................................................ -- -- 92 -------- -------- -------- Net cash provided by financing activities .................. (1,484) 5,045 3,817 -------- -------- -------- Net increase (decrease) in cash and cash equivalents ....... (422) (699) 691 Cash and cash equivalents at beginning of year ............................ 1,356 2,055 1,364 -------- -------- -------- Cash and cash equivalents at end of year .................................. $ 934 $ 1,356 $ 2,055 ======== ======== ========

The accompanying notes are an integral part of these financial statements. 22 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (000s)

SHARES OF SHARES OF ADDITIONAL TOTAL COMMON TREASURY COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS' STOCK STOCK STOCK CAPITAL EARNINGS STOCK EQUITY --------- -------- -------- ---------- -------- -------- ------------ Balance, December 31, 1997 ....... 8,520 (28) $ 85 $ 42,729 $ 9,189 $ (455) $ 51,548 Net loss ......................... -- -- -- -- (1,211) -- (1,211) Exercise of options .............. 11 -- -- 89 -- -- 89 Acquisition of treasury stock .... -- (63) -- -- -- (690) (690) Reissuance of treasury stock ..... -- 31 -- (79) -- 375 296 Other ............................ -- -- -- (46) -- 49 3 ------- ------ -------- -------- -------- -------- -------- Balance, December 31, 1998 ....... 8,531 (60) $ 85 $ 42,693 $ 7,978 $ (721) $ 50,035 Net income ....................... -- -- -- -- 2,823 -- 2,823 Acquisition of treasury stock .... -- (156) -- -- -- (1,035) (1,035) Reissuance of treasury stock ..... -- 147 -- (471) -- 1,367 896 ------- ------ -------- -------- -------- -------- -------- Balance, December 31, 1999 ....... 8,531 (69) $ 85 $ 42,222 $ 10,801 $ (389) $ 52,719 Net income ....................... -- -- -- -- 8,878 -- 8,878 Issuance of common stock ......... 30 (30) 1 197 -- (198) -- Exercise of options .............. -- 5 -- 10 -- 28 38 Acquisition of treasury stock .... -- (39) -- -- -- (251) (251) Reissuance of treasury stock ..... -- 29 -- 42 -- 168 210 ------- ------ -------- -------- -------- -------- -------- Balance, December 31, 2000 ....... 8,561 (104) $ 86 $ 42,471 $ 19,679 $ (642) $ 61,594 ======= ====== ======== ======== ======== ======== ========

The accompanying notes are an integral part of these financial statements. 23 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS MarkWest Hydrocarbon, Inc. ("MarkWest" or the "Company"), provides natural gas processing and related services. The Company's activities include compression, gathering, treatment and natural gas liquids ("NGLs") extraction services for natural gas producers and pipeline companies and fractionation of NGLs into marketable products. The Company also purchases, stores and markets natural gas and NGLs and conducts strategic exploration for natural gas sources for its processing services. The Company's operations are concentrated in three core areas: the southern Appalachian region of eastern Kentucky, southern West Virginia, and southern Ohio; Michigan; and the Rocky Mountains. NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries: MarkWest Resources, Inc.; MarkWest Michigan, Inc.; Basin Pipeline, LLC; West Shore Processing Company, LLC; and Matrex, LLC. All significant intercompany accounts and transactions have been eliminated in consolidation. CASH AND CASH EQUIVALENTS The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Investments are limited to overnight investments of end-of-day cash balances. INVENTORIES Inventories comprise the following (in 000s):

At December 31, ------------------ 2000 1999 ------ ------ Product inventory .................. $7,973 $5,629 Materials and supplies inventory ... 85 414 ------ ------ $8,058 $6,043 ====== ======

Product inventory consists primarily of finished goods (propane, butane, isobutane, natural gasoline and natural gas) and is valued at the lower of cost, using the first-in, first-out method, or market. Materials and supplies are valued at the lower of average cost or estimated net realizable value. PREPAID FEEDSTOCK Prepaid feedstock consists of natural gas purchased in advance of its actual use. It is valued using the first-in/first-out method. PROPERTY AND EQUIPMENT Property and equipment is recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related asset's estimated useful life. Depreciation is provided principally on the straight-line method over the following estimated useful lives: plant facilities and pipelines, 20 years; buildings, 40 years; furniture, leasehold improvements and other, 3 to 10 years. Oil and gas properties and equipment consist of leasehold costs, producing and non-producing properties, oil and gas wells, equipment and pipelines. The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized to the full cost pool. Depletion for oil and gas properties is provided for using the units-of-production method. These capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage value, are amortized on a units-of-production basis using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment of such properties indicate that the properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized. As of December 31, 2000 and 1999, approximately $0.6 million and $1.2 million of investments in unproved properties were excluded from amortization. 24 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The capitalized costs included in the full cost pool are subject to a "ceiling test," which limits such costs to the aggregate of the estimated present value, using a 10 percent discount rate, of the future net revenues from proved reserves, based on current economics and operating conditions. No impairment existed during the three years ended December 31, 2000. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the consolidated statement of operations. INTANGIBLE ASSETS Intangible assets consist primarily of deferred financing costs that are amortized over the anticipated term of the associated agreement. HEDGING ACTIVITIES The Company limits its exposure to natural gas and propane price fluctuations related to future purchases and production with futures contracts. These contracts are accounted for as hedges in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 80, ACCOUNTING FOR FUTURES CONTRACTS. Gains and losses on such hedge contracts are deferred and included as a component of revenues or cost of sales when the hedged production is sold. See also Note 8, Adoption of SFAS No. 133. FAIR VALUE OF FINANCIAL INSTRUMENTS The Company's financial instruments consist of cash and cash equivalents, receivables, accounts payable and other current liabilities, and long-term debt. Except for long-term debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 2000 and 1999, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount. REVENUE RECOGNITION Revenue for sales or services provided under contractual arrangements, is recognized at the time the title is transferred or at the time the service is performed. INCOME TAXES Deferred income taxes reflect the impact of "temporary differences" between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined in accordance with the liability method of accounting for income taxes as prescribed by SFAS No. 109, ACCOUNTING FOR INCOME TAXES. CONCENTRATION OF CREDIT RISK Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable. The trade accounts receivable risk is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations. At December 31, 2000 and 1999, the Company had no significant concentrations of credit risk. STOCK COMPENSATION As permitted under SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, the Company has elected to continue to measure compensation costs for stock- based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. See Note 10 for the applicable disclosures required by SFAS No. 123. EARNINGS PER SHARE Basic earnings per share are determined by dividing net income (loss) by the weighted-average number of common shares outstanding during the year. Earnings per share assuming dilution are determined by dividing net income by the weighted-average number of common shares and common stock equivalents outstanding. 25 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEGMENT REPORTING In accordance with SFAS No. 131, DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, the internal organization that is used by management for making operating decisions and assessing performance is the source of the Company's reportable segments (see Note 12, SEGMENT REPORTING). SUPPLEMENTAL CASH FLOW INFORMATION

Year Ended December 31, (in millions) --------------------------- 2000 1999 1998 ------ ------ ------ Interest paid ............................................ $ 2.5 $ 2.7 $ 2.4 Interest expense capitalized to various construction projects .............................................. $ 0.1 $ 0.2 $ 0.3 Income taxes paid (net of refunds) ....................... $ 2.0 $ (1.5) $ 0.5

Non-cash investing activities in 1998 included the forgiveness of a note and related interest receivable valued at $10.1 million in exchange for the title to a 32-mile pipeline in Michigan. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards (`SFAS") No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. This statement, as amended by SFAS Nos. 137 and 138, is effective for fiscal years beginning after June 15, 2000. SFAS No. 133 requires an entity to recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value. The Company has adopted SFAS No. 133, as amended, on January 1, 2001. See Note 8, Adoption of SFAS 133. In December 1999, the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin ("SAB") No. 101, REVENUE RECOGNITION IN FINANCIAL STATEMENTS, that provides guidance on the recognition, presentation and disclosure of revenue in financial statements filed with the SEC. The adoption of the SAB had no effect on the Company's financial position or net income. The Emerging Issues Task Force of FASB, issued EITF Issue No. 00-10 "Accounting for Shipping and Handling Fees and Costs". This issue addresses the statement of income classification of shipping and handling costs billed to customers and was effective for the fourth quarter of 2000. This has been adopted and prior period amounts were reclassified to conform to the new requirement. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. RECLASSIFICATIONS Certain prior year amounts have been reclassified to conform to the 2000 presentation. NOTE 3. DEBT CREDIT FACILITY Effective May 26, 2000, the Company amended its existing credit agreement. The amended agreement has been extended for an additional year, through the year 2006, and provides for a $15 million increase to the maximum borrowing amount, now $65 million, pursuant to a revolving loan commitment. Actual borrowing limits may be a lesser amount, depending on trailing cash flow, as defined in the agreement. The credit facility permits the Company to borrow money using either a base rate loan or a London Interbank Offered Rate loan option, plus an applicable margin of between 0 percent and 2.75 percent, based on a certain Company debt to earnings ratio. At December 31, 2000, the Company had $43 million outstanding under the credit facility bearing interest at a weighted average rate of 8.27 percent. At December 31, 1999, the Company had $40.5 million outstanding under the credit facility bearing interest at a weighted average rate of 9.25 percent. The Company pays a fee at a rate between 0.25 percent and 0.50 26 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS percent per annum on the unused commitment, based on a certain Company debt to earnings ratio. The credit facility is collateralized by a first mortgage on the Company's major assets. The loan agreement restricts certain activities and requires the maintenance of certain financial ratios and other conditions. 155 INVERNESS BUILDING LOAN Effective January 14, 1998, the Company's wholly owned subsidiary, 155 Inverness, Inc., obtained a $3.7 million loan from an insurance company to refinance an office building. As of December 31, 1999, approximately $3.6 million was outstanding under the note. The Company sold the office building in February 2000 for net cash proceeds of $5.0 million and repaid the loan. SCHEDULED DEBT MATURITIES Scheduled debt maturities as of December 31, 2000, are as follows (in 000s): 2001 ................................. $ 0 2002 ................................. 0 2003 ................................. 0 2004.................................. 10,500 2005 and thereafter................... 32,500 ---------- Total................................. $ 43,000 ========== NOTE 4. RELATED PARTY TRANSACTIONS The Company, through its wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), holds varied undivided interests in several exploration and production assets owned jointly with MAK-J Energy Partners Ltd. ("MAK-J"), which owns a 51 percent undivided interest in such properties. The general partner of MAK-J is a corporation owned and controlled by the President and Chief Executive Officer of the Company. The properties are held pursuant to operating agreements entered into between Resources and MAK-J. Resources is the operator under such agreements. As the operator, Resources is obligated to provide certain engineering, administrative and accounting services to the joint ventures. The joint venture agreements provide for a monthly fee payable to Resources for all such expenses. As of December 31, 2000 and 1999, the Company has receivables due from MAK-J for approximately $2,242,000 and $426,000, and payables to MAK-J for approximately $773,000 and $400,000, respectively. The Company made contributions of $475,000, $328,000 and $164,000 to a profit-sharing plan for the years ended December 31, 2000, 1999 and 1998, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors. NOTE 5. LEASE OBLIGATIONS The Company has various non-cancelable operating lease agreements for equipment and office space expiring at various times though fiscal 2015. Annual rent expense under these operating leases was approximately $1,755,000, $893,000 and $222,000 for the years ended December 31, 2000, 1999 and 1998, respectively. The Company's minimum future lease payments under these operating leases as of December 31, 2000 are as follows (in 000s): 2001 ................................. $ 1,984 2002 ................................. 1,910 2003.................................. 1,853 2004.................................. 1,736 2005.................................. 1,748 2006 and thereafter................... 5,562 ---------- Total................................. $ 14,793 ========== NOTE 6. SIGNIFICANT CUSTOMERS For the year ended December 31, 2000, sales to one customer accounted for approximately 11 percent of total revenues. Management believes the loss of this customer would not adversely impact operations, because alternative markets are available. There were no significant customers in 1999 and 1998. 27 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 7. COMMODITY PRICE RISK MANAGEMENT The Company's primary risk management objective is to reduce volatility in its cash flows. Its hedging approach uses a statistical method that analyzes momentum and average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. Hedging levels increase with capital commitments and debt levels and when above-average margins exist. The Company maintains a committee, including members of senior management, which oversees all hedging activity. MarkWest achieves its goals utilizing a combination of fixed-price forward contracts and fixed-for-float price swaps on the over-the-counter ("OTC") market. New York Mercantile Exchange ("NYMEX")-traded futures are authorized for use, but only occasionally used. Swaps and futures allow the Company to protect margins, because gains or losses in the physical market are generally offset by corresponding losses or gains in the value of financial instruments. The Company enters OTC swaps with counterparties that are primarily other energy companies. The Company conducts a standard credit review and has agreements with such parties that contain collateral requirements. The Company uses standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. The Company is subject to margin deposit requirements under OTC agreements (and NYMEX positions). The use of financial instruments may expose the Company to the risk of financial loss in certain circumstances, including instances when (a) sales volumes are less than expected requiring market purchases to meet commitments, or (b) the Company's OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGL, or crude oil or otherwise fail to perform. To the extent that the Company engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, it is similarly insulated against decreases in such prices. MarkWest hedges its basis risk for natural gas but is generally unable to do so for NGLs. The Company's basis risk stems from the geographic price differentials between MarkWest's sales locations and hedging contract delivery locations. Basis risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged. In its gathering, processing and marketing segment, the Company hedges Appalachia processing margins by using a combination of methods. MarkWest protects margins by purchasing natural gas priced on predetermined Btu differentials to propane or crude, by simultaneously selling propane or crude oil and purchasing natural gas, and by using swaps. Crude oil is highly correlated with certain NGL products. All projected margins on open positions assume the basis differentials between the Company's sales location and the hedging contract's specified location and assume the correlation between crude oil and NGLs is consistent with historical averages. As of December 31, 2000, the Company had hedged 17,500,000 NGL gallons at a $0.22 per gallon processing margin for 2001. For certain Appalachia natural gas sales, as of December 31, 2000, the Company had hedged 650,000 and 54,000 MMBtu at $4.86 and $5.19 per MMBtu for 2001 and 2002 respectively. In addition to these risk management tools, MarkWest utilizes its NGL storage facilities and contracts for third-party storage to build product inventories during historically lower-priced periods for resale during higher-priced periods. Also, MarkWest has contracts to purchase certain quantities of its natural gas feedstock in advance of physical needs. In its exploration and production segment, the Company also hedges its exposure to changes in market prices for its natural gas production. As of December 31, 2000, the Company had hedged 1,226,000, 530,000 and 273,000 MMBtu of natural gas sales at prices of $3.28, $3.45 and $3.92 per MMBtu for 2001, 2002 and 2003, respectively. The Company enters into speculative transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such transactions. Speculative transactions are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period. There were no such speculative activities for the years ended 2000, 1999 and 1998. NOTE 8. ADOPTION OF SFAS NO. 133 The company is adopting Statement of Financial Accounting Standards No. 133 (SFAS 133), ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, as amended, on January 1, 2001. In accordance with the transition provisions of SFAS 133, the Company will record on that date a net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. The Company expects to reclassify as 28 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS earnings during the next twelve months approximately $0.8 million loss from the transition adjustment that was recorded in other comprehensive income. SFAS 133 establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset of liability measured at fair value. Changes in the derivative instruments' fair value are recognized in earnings unless specific hedge accounting criteria are met. SFAS 133 allows hedge accounting for fair-value and cash-flow hedges. A fair-value hedge applies to a recognized asset or liability or an unrecognized firm commitment. A cash-flow hedge applies to a forecasted transaction or a variable cash flow of a recognized asset or liability. SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair-value hedging instrument as well as the offsetting loss or gain on the hedged item be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash-flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. (The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.) Effectiveness is evaluated by the derivative instrument's ability to generate offsetting changes in fair value or cash flows to the hedged item. The Company expects its hedging activities will generally qualify as cash-flow hedges. The Company formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment. In its gathering, processing and marketing segment, the Company enters into fixed-price contracts for the sale of NGLs and fixed-price purchases for the purchase of natural gas, the difference in value being the "processing margin". At January 1, 2001, a derivative asset of approximately $2.1 million will be recorded in the balance sheet with an offsetting amount recorded, less a deferred tax liability of approximately $0.7 million, in other comprehensive income, approximately $1.3 million gain. In its exploration and production segment, the Company enters into fixed price contracts for the sale of natural gas. At January 1, 2001, a derivative liability of approximately $3.9 million will be recorded in the balance sheet with an offsetting amount recorded, less a deferred tax recovery of approximately $1.4 million, in other comprehensive income, approximately $2.5 million loss. Together, these amounts comprise the above net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income. 29 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 9. INCOME TAXES The provision (benefit) for income taxes is comprised of (in 000s):

Year Ended December 31, ---------------------------------- 2000 1999 1998 ------- ------- ------- Current: Federal ............... $ 1,260 $ 788 $(1,921) State ................. 406 (29) (314) ------- ------- ------- Total current ......... 1,666 759 (2,235) ------- ------- ------- Deferred: Federal ............... 2,697 664 1,413 State ................. 525 278 55 ------- ------- ------- Total deferred ........ 3,222 942 1,468 ------- ------- ------- Total tax provision ... $ 4,888 $ 1,701 $ (767) ======= ======= =======

The deferred tax liabilities (assets) are comprised of the tax effect of the following at December 31 (in 000s):

2000 1999 -------- -------- Property and equipment ................................. $ 13,030 $ 9,840 Other assets ........................................... 296 224 -------- -------- Total deferred income tax liabilities ............. 13,326 10,064 -------- -------- Alternative minimum tax ("AMT") credit carryforward .... (2,031) (1,888) State net operating loss ("NOL") carryforwards ......... (49) (151) Intangible assets ...................................... (6) (6) -------- -------- Total deferred income tax assets .................. (2,086) (2,045) -------- -------- Net deferred tax liability ........................ $ 11,240 $ 8,019 ======== ========

The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes subsequent to reorganization, are summarized as follows (in 000s):

2000 % 1999 % 1998 % ------- ------ ------- ------ ------- ------ Income tax (benefit) at statutory rate ......... $ 4,818 35.0% $ 1,583 35.0% $ (672) (34.0%) State income taxes, net of federal benefit ..... 603 4.4% 168 3.7% (102) (5.1%) Credits ........................................ (558) (4.1%) (75) (1.7%) -- -- Other .......................................... 25 0.2% 25 0.6% 7 0.3% ------- ------ ------- ------ ------- ------ Total .................................... $ 4,888 35.5% $ 1,701 37.6% $ (767) (38.8%) ======= ====== ======= ====== ======= ======

30 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS At December 31, 2000, the Company had state NOL carryforwards for state income tax purposes and AMT credit carryforwards for federal income tax purposes of approximately $1.1 million and $2.0 million, respectively. These carryforwards expire as follows (000s):

State Expiration Dates NOL AMT ---------------- ------- -------- 2014.......................... $ 160 $ -- 2015.......................... 895 -- No expiration................. -- 2,031 ------- -------- Total.................... $ 1,055 $ 2,031 ======= ========

The Company believes that the state NOL carryforwards and AMT credit carryforwards will be fully utilized. They are expected to be offset by existing taxable temporary differences reversing within the carryforward period or are expected to be realized by achieving future profitable operations based on the Company's dedicated and owned reserves, dedicated reserves behind its processing plants, past earnings history, and projections of future earnings. NOTE 10. STOCK COMPENSATION PLANS At December 31, 2000, the Company has two stock-based compensation plans, which are described below. The Company applies APB Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES, and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its fixed stock option plans. Had compensation cost for the Company's two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, the Company's pro forma net income and earnings per share would have been reduced to the pro forma amounts listed below (in 000s, except per share data):

2000 1999 1998 ------- ------- -------- Net income (loss) As reported............. $ 8,878 $ 2,823 $ (1,211) Pro forma............... 8,409 2,428 (1,483) Basic earnings (loss) per share As reported............. $ 1.05 $ 0.33 $ (0.14) Pro forma............... 0.99 0.29 (0.17) Earnings (loss) per share As reported............. $ 1.05 $ 0.33 $ (0.14) assuming dilution Pro forma............... 0.99 0.29 (0.17)

Under the 1996 Stock Incentive Plan, the Company may grant options to its employees for up to 850,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of the grant, and an option's maximum term is ten years. Options are granted periodically throughout the year and vest at the rate of 25 percent per year for options granted in 1999 and after, and 20 percent per year for options granted prior to 1999. Under the 1996 Non-employee Director Stock Option Plan, the Company may grant options to its non-employee directors for up to 20,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of the grant, and an option's maximum term is three years. Options are granted upon the date the director first becomes a director and biannually thereafter. Options granted upon the date the director first becomes a director vest at the rate of 33.33 percent per year. Biannual options vest 100 percent on the first anniversary of the option grant date. On October 1, 1998, the Company repriced all stock options granted in 1997 and mid-1998. The stock options were repriced at $10.75 per share, the fair market value on October 1, 1998. The fair value of each option is estimated on the date of grant using the Black-Scholes Option Pricing model with the following weighted-average assumptions: dividend yield of $0/share for options granted in 2000, 1999 and 1998; expected volatility of 43 percent for the 2000 option grants, 40 percent for the 1999 option grants and 34 percent for 1998 option grants; risk-free interest rate of 5.93 percent for 2000 option grants, 6.22 percent for 1999 option grants and 4.35 percent for 1998 option grants; expected lives of 6 years for 2000, 1999 and 1998 option grants. 31 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of the status of the Company's two fixed stock option plans as of December 31, 2000, 1999 and 1998, and changes during the years ended on those dates are presented below:

2000 1999 1998 ------------------------ -------------------- ----------------------- Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price -------- -------- -------- -------- -------- --------- FIXED OPTIONS Outstanding at beginning of year ............ 621,117 $ 9.15 514,503 $ 9.78 383,490 $ 12.50 Granted ..................................... 150,317 9.94 141,672 7.03 374,162 11.53 Exercised ................................... (4,655) 9.92 -- -- (11,482) 7.73 Canceled .................................... (26,533) 9.10 (35,058) 9.86 (231,667) 17.21 -------- -------- -------- -------- -------- --------- Outstanding at end of year .................. 740,246 $ 9.15 621,117 $ 9.15 514,503 $ 9.78 ======== ======== ======== ======== ======== ========= Options exercisable at December 31, 2000, 1999 and 1998, respectively .............. 342,914 230,808 148,840 Weighted-average fair value of options granted during the year .......... $ 4.93 $ 3.42 $ 4.72

The following table summarizes information about fixed stock options outstanding at December 31, 2000:

Options Outstanding Options Exercisable ------------------------------------------------- ----------------------------- Weighted- Average Weighted- Weighted- Number Remaining Average Number Average Outstanding Contractual Exercise Exercisable Exercise Range of Exercise Prices at 12/31/00 Life Price At 12/31/00 Price ------------------------ ----------- ----------- --------- ----------- --------- $ 5.38 to $7.25............. 148,790 5.4 $ 6.29 98,862 $ 6.71 $ 7.28 to $8.75............. 150,761 8.2 8.54 32,386 8.12 $ 9.00 to $10.50............ 170,755 5.7 10.18 102,475 10.13 $10.75 to $10.75............ 196,754 6.7 10.75 109,191 10.75 $11.25 to $11.25............ 73,186 9.6 11.25 0 0.00 --------- ----- ------- --------- ------- $ 5.38 to $11.25............ 740,246 6.8 $ 9.32 342,914 $ 9.15 ========= ===== ======= ========= =======

NOTE 11. EARNINGS PER SHARE The following table shows the amounts used in computing earnings per share and weighted average number of shares of dilutive potential common stock for the years ended December 31, 2000, 1999 and 1998 (in 000s, except per share data):

For the Year Ended December 31, --------------------------------- 2000 1999 1998 ------- ------- ------- Net income (loss) ........................... $ 8,878 $ 2,823 $(1,211) ======= ======= ======= Weighted average number of outstanding shares of common stock used in earnings per share ................................. 8,452 8,475 8,490 Effect of dilutive securities: Stock options ............................. 40 6 -- ------- ------- ------- Weighted average number of outstanding shares of common stock used in earnings per share assuming dilution ............... 8,492 8,481 8,490 ======= ======= =======

32 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 12. SEGMENT REPORTING The Company's operations are classified into two principal reportable segments, as follows: (1) Gathering, Processing and Marketing-provide compression, gathering, treatment, NGL extraction and fractionation services; also purchase and market natural gas and NGLs; and (2) Exploration and Production-explore for and produce natural gas. MarkWest evaluates the performance of its segments and allocates resources to them based on expected gross operating income. There are no intersegment revenues. MarkWest's business is conducted solely in the United States. The table below presents information about operating income for the reported segments for the three years ended December 31, 2000. Operating income for each segment includes total revenues less operating expenses, and excludes depreciation, depletion and amortization, corporate administrative expenses, interest expense, interest income and income taxes. Asset information by reportable segment is not reported, since MarkWest does not produce such information internally.

Gathering, Processing Exploration and and Marketing Production Total (000s) (000s) (000s) --------------------- --------------- --------- FOR THE YEAR ENDED DECEMBER 31, 2000 Revenues ........................... $217,393 $ 4,161 $221,554 Segment operating income ........... $ 29,035 $ 1,899 $ 30,934 FOR THE YEAR ENDED DECEMBER 31, 1999 Revenues ........................... $105,150 $ 1,860 $107,010 Segment operating income ........... $ 16,419 $ 620 $ 17,039 FOR THE YEAR ENDED DECEMBER 31, 1998 Revenues ........................... $ 63,190 $ 1,415 $ 64,605 Segment operating income ........... $ 9,593 $ 361 $ 9,954

A reconciliation of total segment operating income to total consolidated income (loss) before taxes is as follows (000s):

2000 1999 1998 -------- -------- -------- Total segment operating income ........ $ 30,934 $ 17,039 $ 9,954 General and administrative expenses ... (8,761) (6,986) (5,319) Depreciation and amortization ......... (6,314) (5,070) (4,594) Interest income ....................... 101 53 200 Interest expense ...................... (3,110) (2,745) (2,095) Gain on sale of assets ................ 1,000 2,509 Other income (expense) ................ (84) (276) (124) -------- -------- -------- Income (loss) before taxes ....... $ 13,766 $ 4,524 $ (1,978) ======== ======== ========

NOTE 13. SUBSEQUENT EVENTS a) In January 2001, MarkWest Hydrocarbon, Inc. purchased natural gas properties in San Juan County, New Mexico, for $5.6 million. b) In February 2001, three complaints were filed against MarkWest Hydrocarbon, Inc. in the Circuit Court of Wayne County, West Virginia, by Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy LLC; and Cobra Petroleum Company et al. These complaints each allege breach of contract and seek various forms of relief (including injunctive relief) and damages. The parties have agreed to a temporary standstill to the litigation and are currently negotiating a resolution to this dispute. There can be no assurance that these negotiations will be successful or that the outcome of the litigation or the settlement discussions will be favorable to the Company. Losses, if any, with regard to these complaints are undeterminable. 33 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 14. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following summarizes certain quarterly results of operations (in 000s):

First Second Third Fourth ----- ------ ----- ------ 2000 ---- Operating revenue ...................... $ 45,125 $ 39,328 $ 56,518 $ 80,583 Income from operations (1) ............. 6,034 1,343 3,005 5,477 Net income (2) ......................... 3,255 1,107 1,325 3,191 Basic earnings per share ............... 0.39 0.13 0.16 0.38 Earnings per share assuming dilution ... 0.38 0.13 0.16 0.38 1999 ---- Operating revenue ...................... $ 22,093 $ 17,978 $ 30,484 $ 36,455 Income (loss) from operations (1) ...... 960 (908) 542 4,389 Net income (3) ......................... 110 577 59 2,077 Basic earnings per share ............... $ 0.01 $ 0.07 $ 0.01 $ 0.24 Earnings per share assuming dilution ... $ 0.01 $ 0.07 $ 0.01 $ 0.24

------------------- (1) Excludes interest income and expense, other income and expense, and gain on sale of assets. (2) Includes $1.0 million gain ($0.6 million, or $0.07 per share, after tax) on the sale of an asset, second quarter of 2000. (3) Includes $2.5 million gain ($1.5 million, or $0.18 per share, after tax) on the sale of an asset, second quarter of 1999. NOTE 15. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) COSTS The following tables set forth capitalized costs at December 31, 2000, 1999 and 1998, and costs incurred for exploration and production activities for the years ended December 31, 2000, 1999 and 1998 (in 000s):

2000 1999 1998 -------- -------- -------- Capitalized costs: Proved properties ............................ $ 12,481 $ 11,167 $ 8,001 Unproved properties .......................... 4,072 1,972 1,206 Equipment and facilities ..................... 1,484 1,379 1,349 -------- -------- -------- Total ................................................ 18,037 14,518 10,556 Less accumulated depreciation, depletion and amortization .......................... (2,018) (1,362) (801) -------- -------- -------- Net capitalized costs ................................ $ 16,019 $ 13,156 $ 9,755 ======== ======== ======== Costs incurred: Acquisition of properties Proved ....................................... $ 1,191 $ 1,503 $ 2,632 Unproved ..................................... 166 728 12 Development costs .................................... 1,818 1,776 559 Exploration costs .................................... 971 435 284 -------- -------- -------- Total costs incurred ................................. $ 4,146 $ 4,442 $ 3,487 ======== ======== ========

34 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS RESULTS OF OPERATIONS The results of operations for exploration and production activities, excluding corporate overhead and interest costs, for the years ended December 31, 2000, 1999 and 1998 are as follows (in 000s):

2000 1999 1998 ------- ------- ------- Revenues: Sales, net of taxes ..................... $ 3,874 $ 1,678 $ 1,375 Other ................................... 287 182 40 ------- ------- ------- Total ................................... 4,161 1,860 1,415 Cost of sales .............................. (833) (322) (231) Lease operating expense .................... (1,429) (918) (823) ------- ------- ------- Cash operating income ...................... 1,899 620 361 Depreciation, depletion and amortization ... (658) (561) (431) Income tax benefit ......................... 185 53 27 ------- ------- ------- Results of operations ...................... $ 1,426 $ 112 $ (43) ======= ======= =======

RESERVE QUANTITY INFORMATION Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations. The following table sets forth information for the years ended December 31, 2000, 1999 and 1998, with respect to changes in the Company's proved reserves, all of which are in the United States.

2000 1999 1998 ----------- ----------- ----------- Natural Gas Natural Gas Natural Gas (Mcfe) (Mcfe) (Mcfe) ----------- ----------- ----------- Proved developed and undeveloped reserves: Beginning of year .......................... 32,719,560 26,048,300 23,155,910 Revisions of previous estimates ............ (60,116) 1,031,719 1,164,111 Purchase of minerals in place .............. 1,524,400 2,252,853 3,029,036 Extensions and discoveries ................. 2,253,000 4,355,359 129,029 Production ................................. (1,375,506) (968,671) (850,041) Sale of minerals in place .................. (475,800) -- (579,745) ----------- ----------- ----------- End of year ................................ 34,585,538 32,719,560 26,048,300 =========== =========== =========== Proved developed reserves: Beginning of year .......................... 22,113,900 13,664,760 11,025,140 =========== =========== =========== End of year ................................ 22,803,688 22,113,900 13,664,760 =========== =========== ===========

There were no significant oil reserves in any of the years presented. STANDARDIZED MEASURES OF DISCOUNTED FUTURE NET CASH FLOWS Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES. Certain information concerning the assumptions used in computing the valuation of proved 35 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements, including hedging contracts in existence at year-end. The assumptions used to compute estimated future net revenues do not necessarily reflect the Company's expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the Company's proved reserves. Permanent differences in natural gas-related tax credits and allowances are recognized. An annual discount rate of 10 percent was used to reflect the timing of the future net cash flows relating to proved reserves. Information with respect to the Company's estimated discounted future net cash flows from its natural gas properties for the years ended December 31, 2000, 1999 and 1998, is as follows (in 000s):

2000 1999 1998 --------- --------- --------- Future cash inflows ........................................ $ 296,454 $ 75,290 $ 51,055 Future production costs .................................... (52,047) (32,541) (26,886) Future development costs ................................... (1,484) (2,970) (3,623) Future income tax expense .................................. (90,103) (12,982) (7,302) --------- --------- --------- Future net cash flows ...................................... 152,820 26,797 13,244 10% annual discount for estimated timing of cash flows ..... (87,770) (15,332) (8,271) --------- --------- --------- Standardized measure of discounted future net cash flows relating to proved reserves ........................ $ 65,050 $ 11,465 $ 4,973 ========= ========= ========= Discounted future cash flows excluding income taxes ........ $ 97,953 $ 16,122 $ 11,731 ========= ========= =========

Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 2000, 1999 and 1998, are as follows (in 000s):

2000 1999 1998 -------- -------- -------- January 1 .................................................................... $ 11,465 $ 4,973 $ 8,060 Sales and transfers of natural gas produced, net of production costs ...... (1,899) (620) (361) Net changes in prices and production costs related to future production ... 72,526 3,332 (3,158) Previously estimated development costs incurred during the period ......... 1,816 654 355 Changes in estimated future development costs ............................. (315) -- (339) Extensions and discoveries ................................................ 7,429 3,260 81 Revisions of previous quantity estimates .................................. 213 492 316 Purchases of reserves in place ............................................ 4,468 1,432 1,471 Sales of reserves in place ................................................ (177) -- (673) Changes in production rates and other ..................................... (3,841) (708) (2,116) Accretion of discount ..................................................... 1,612 753 1,086 Net change in income taxes ................................................ (28,247) (2,103) 251 -------- -------- -------- December 31 .................................................................. $ 65,050 $ 11,465 $ 4,973 ======== ======== ========

36 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted because the Company will file a definitive proxy statement pursuant to Regulation 14A under the Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the definitive proxy statement to be so filed for the Company's 2001 annual meeting of stockholders hereby incorporated by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: (1) Financial Statements: Reference is made to the Index to Consolidated Financial Statements included in this Form 10-K for a list of all financial statements filed as a part of this report. (2) Financial Statement Schedules: None required. (3) Exhibits: See (c) below. (b) Reports on Form 8-K: A report on Form 8-K was filed on February 22, 2001, concerning the litigation described in Item 3-Legal Proceedings. A report on Form 8-K was filed on November 15, 2000, announcing the acquisition of additional coal bed methane properties in New Mexico's San Juan Basin. The deal closed January 2001. (c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above. 2.1 Purchase and Sale Agreement between MarkWest Hydrocarbon, Inc., and Michigan Energy Company, L.L.C., dated November 21, 1997 (filed as Exhibit 2.1 to MarkWest Hydrocarbon, Inc.'s Form 8-K filed on January 29, 1998, and incorporated herein by reference). 3.1 Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (filed as Exhibit 3.1). (1) 3.2 Bylaws of MarkWest Hydrocarbon, Inc. (1) 10.1 Amended and Restated Reorganization Agreement made as of August 1, 1996, by and among MarkWest Hydrocarbon, Inc.; MarkWest Hydrocarbon Partners, Ltd.; MWHC Holding, Inc.; RIMCO Associates, Inc.; and each of the limited partners of MarkWest Hydrocarbon Partners, Ltd. (1) 10.2 1996 Incentive Compensation Plan (filed as Exhibit 10.25). (1) 10.3 1996 Stock Incentive Plan (filed as Exhibit 10.26). (1) 10.4 1996 Non-employee Director Stock Option Plan (filed as Exhibit 10.27). (1) 10.5 Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc. (filed as Exhibit 10.28). (1) 10.6 MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended September 30, 1997, and incorporated herein by reference). 10.7 Second Amended and Restated Credit Agreement, dated as of September 29, 1999, among MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of America, N.A., as the Administrative Agent and the Syndication Agent for the Lenders (filed as Exhibit 10 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended September 30, 1999, and incorporated herein by reference). 10.8 First Amendment to Second Amended and Restated Credit Agreement, dated as of May 26, 2000 among MarkWest Hydrocarbon, Inc., as the Borrower and Certain Commercial Lending Institutions, as the Lenders, and Bank of America, N.A., as the Administrative and Syndication Agent for the Lenders. 11. Statement regarding computation of earnings per share. 21. List of Subsidiaries of MarkWest Hydrocarbon, Inc. 23.1 Consent of PricewaterhouseCoopers LLP 23.2 Consent of Cawley, Gillespie & Associates, Inc. ------------------- (1) Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513. 37 SIGNATURES Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Englewood, State of Colorado, on March 26, 2001. MarkWest Hydrocarbon, Inc. (Registrant) BY: /s/ John M. Fox ------------------------ John M. Fox President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ John M. Fox March 26, 2001 ----------------------------------- John M. Fox President, Chief Executive Officer and Director /s/ Brian T. O'Neill March 26, 2001 ----------------------------------- Brian T. O'Neill Senior Vice President, Chief Operating Officer and Director /s/ Gerald A. Tywoniuk March 26, 2001 ----------------------------------- Gerald A. Tywoniuk Chief Financial Officer and Vice President of Finance (Principal Financial and Accounting Officer) /s/ Arthur J. Denney March 26, 2001 ----------------------------------- Arthur J. Denney Senior Vice President of Engineering and Project Management and Director /s/ William A. Kellstrom March 26, 2001 ----------------------------------- William A. Kellstrom Director /s/ Karen L. Rogers March 26, 2001 ----------------------------------- Karen L. Rogers Director /s/ Barry W. Spector March 26, 2001 ----------------------------------- Barry W. Spector Director /s/ Donald D. Wolf March 26, 2001 ----------------------------------- Donald D. Wolf Director 38